CORROSION 2010

Until recently, there was not a resistance equation for multiple horizontal anode groundbeds. In the case when the anodes are in the same coke breeze bed, the groundbed resistance can be calculated with the Dwight'si single horizontal anode equation.

In the case of several horizontal anodes in an individual coke bed, an interference factor between anodes, some times called the crowed factor, is used. The interference factor is derived from Sunde's vertical resistance equation for multiple anodesii.

This paper presents two general equations for horizontal anode groundbeds, with the anodes in individual coke breeze beds. The first case describes anodes that are in a parallel configuration, while the second one is for when anodes are placed in the same line, but still in an individual coke breeze bed.

An analysis of the Sunde's equation for multiple electrodes in horizontal configurationsiii is done in order to show that this equation cannot be used in the case of typical cathodic protection designs.

This paper offers a more accurate approach to the horizontal anode groundbed design and helps in the understanding of the general theory behind the groundbed resistance equations.

INTRODUCTION

The resistance of a buried straight wire (electrode, anode) of length L, no part of which is near the surface of the ground (electrically remote from earth surface) was obtained by Dwight, using the equation of a potential in a charged ring, the average potential method, and the relationship between the capacitance of two parallel plates and resistance to ground iv.

The average potential method consists of assuming uniform charge density over the surface of the conductor and calculating the average potential. Then the approximate capacitance is taken to be equal to the total charge divided by the average potential.

The equation that relates the resistance with the capacitance in the case of an electrode in infinite space is:

(Equation in full paper)

Sunde applied a very different approach for the case of two or more parallel horizontal electrodesxiv, regarding that the distance between the electrode and its image 2*t and between electrodes S is muless than the electrode's length. This approach could be accurate for the case of multiple horizontal grounding wires, where the grounding wires are much larger than the wire's diameter and greater thanthe distance between wires. In the case of cathodic protection, this approach would be good for long horizontal electrodes, such as ceramic anodes, or when long zinc strips are placed parallel to theto protect against DC and AC fault currents. In general, this approach is not accurate for regular horizontal cathodic protection anodes in individual coke breeze beds, where the distance between anodes and the anode's depth are about the length of the anodes, and in some cases larger than the length of the anode.

If the Dwight method can be extrapolated for the case of any amount of anodes, the case of long or short anodes will be included.

Rotating components in pumps are subjected to a high degree of wear when multiphase fluids containing corrosive elements as well as erosive particles are transported. The wear of these components leads to an increasing loss of efficiency and eventually to the failure of the pump. If the pump is to be used as a stand-alone system such as in ultradeep subsea applications in the oil and gas production industry, the wear has to be minimized. In this paper the wear resistance of USN S43100 steel as a rotating test sample with and without erosive particles in standardised formation water with CO2 is investigated at controlled potentials around the corrosion potential on both the anodic and the cathodic side. As a result it will be shown, that the metal loss of a rotating component is ten times higher than the metal loss of a identical, fixed component in the same environment. Furthermore it will be shown, that the corrosion potential is greatly influenced by the presence of erosive particles. In the case of anodic dissolution, pitting corrosion was found to be the prevalent cause for the metal loss.

INTRODUCTION

Multiphase pumps (MPPs) have been used by the oil and gas production industry since the mid 1980s. They are used to boost the production flow line pressure in order to lower wellhead backpressures as illustrated in figure 1. This will not only allow for longer operational time, i.e. greater field recovery of a reservoir than would otherwise be possible, it also allows for a greater payoff in the initial stages of operation. As illustrated in figure 1, when booster pumps are installed downstream of production wells, the effect will be as if the wellhead pressures themselves were increased. The flow from the well will increase until a new balance between the production from the wells and the system resistance is achieved. The effect is a net increase in oil production.1,2

Although this technology is very adept at handling the transport of multiphase fluids without prior separation this process can, and in most cases will lead to the wear of pump components that are in contact with the transported medium due to the chemical and physical nature of the fluid mixture. The phases that can be encountered when transporting hydrocarbons are

fluid phases such as oil with different viscosities as well as a chloride ion rich water phase, called formation water,

gas phases, such as natural gas with different chemical compositions often containing carbon dioxide (CO2) and hydrogen sulphide (H2S) and

solid phases such as sand and stones.

The phases can be present in all possible volume factions depending on the nature of the reservoir and can also be subject to frequent changes as production commences. The multiphase pumps used by the industry for transport are either of rotodynamic or of volumetric design. Although there are a number of different pump types used in the industry.

Corrosion destroying of equipment manifests itself in a later stage during exploration of oil fields, when extracted oil is watered and properties of separating stratal water, during extraction, collection and preparation of oil, significantly change, particularly increases in sulfate reducing bacteria (SRB) and concentrations of corrosion aggressive gas products from their activity - hydrogen sulfide. As we know, most corrosion inhibitors and biocides which are applied in oil- gas extraction, consist of nitrogen containing substances, as amino alcohols, imidozolines, amides, etc. The aim of this work is to find an efficient method for obtaining new effective biocides for suppression of sulfate reducing bacteria. Biocide properties of nitrogen containing substances on the basis of olefins have been studied in SRB (sulfate reducing bacteria) and H2S containing medium. Correlation between protective properties of reagent and origin of initial components has been established.

INTRODUCTION

The use of corrosion inhibitors on systems related to the transport of hydrocarbon products and their treatment are common practice in the petrochemical industry. The efficiency of these chemical reagents is affected in many ways by a lot of variables, one of them is the presence of microorganisms. The presence of these microorganisms can modify the metallic surface or cause the formation of corrosion products and layers of chemical substances on the surface1. Sulphate- Reducing bacteria (SRB) play a significant role in the corrosion of stainless steels exposed to marine and soil environment. Sulphate reduction by bacterial species results in the production of H2S, which can significantly influence the anodic and cathodic processes and ultimately enhances the corrosion of materials. Under conductions of bactericidal contamination the traditional methods of corrosive protection of oil field equipment are not effective enough. It is necessary to carry out protection against corrosion in this case with reagents of complex influence, possessing bactericidal and corrosion-inhibiting effect. These reagents are convenient in use, and it is possible to introduce them into the system without interrupting production processes. Inhibitors, which contain two or more functional groups in their molecules 1-6, are widely applied as such reagents. One of the important criteria during the creation of multifunctional inhibitors (biocide) is their chemical structure. Biocides were obtained on the base of olefins which extracted from light oil fractions and were also investigated as corrosion inhibitors in aggressive corrosive medium. Olefin fractions were extracted at 160-180oC and used to synthesize amino alcohols with two hydroxyl groups. On the base of active substance soluble corrosion inhibitor which composes 5% of dosed inhibitor was prepared in water.

EXPERIMENTAL PROCEDURE

The reagent for preventing SRB growth was obtained on the basis of α-olefin C12-C14 fraction. The epoxidation has been conducted by mentioned olefins and hydroperoxide of isopropyl benzene in the ratio 2:1 at 100-110oC and in the presence of molibden-hexa carbonyl containing catalyst. Mo(CO)6 concentration is 0.002 ppm for total reacting ingredients. The reaction was performed for 180 minutes. Optimizing of reaction conditions are presented in the Table 1.

Zirconium is one of a very few materials of construction for processes involving high concentrations of sulfuric acid at temperatures above the atmospheric boiling point. In this severe environment only zirconium or tantalum can be used with any reliability. Most corrosion data for zirconium has been developed using welded wrought material as test coupons. The majority of this information is related to the corrosion resistance of Zr 702 with very little information available for Zr 705. In addition, almost no information is available as to the corrosion resistance of the cast forms of either alloy. This paper presents laboratory data comparing the corrosion resistance of Zr 702 and Zr 705 in the welded and wrought forms and in the cast form in sulfuric acid. A newly expanded iso-corrosion diagram is presented for both wrought and cast Zr 702 and Zr 705. Zr 705 is a zirconium alloy containing 2.5% Niobium. Because of the possibility of hydrogen absorption by the Niobium phase during the corrosion process, hydrogen absorption data is also presented for Zr 705. This hydrogen absorption data is compared with Zr 702 tested under the same conditions.

INTRODUCTION

Frequently users consider Zr 702 and Zr 705 as interchangeable in regards to corrosion. In some cases this is true, but not for sulfuric acid applications. For many applications in the chemical processing industry (CPI) involving sulfuric acid, zirconium is the material of choice. This is especially true in concentrated sulfuric acid and when the operating temperature is above the atmospheric boiling point. Although Zr 702 is the most corrosion resistant of the zirconium alloys for this application, Zr 705 can be used in the form of cast pump parts and for fasteners of various types. There are, however, many differences between the two alloys. Zr 702 is generally more corrosion resistant than Zr 705 but Zr 705 has considerably higher strength and is more formable than Zr 702. Both alloys can be produced into large castings by the rammed graphite casting method [1].

Cast zirconium has similar metallographic structure to that found in the welded wrought material. In both cases, the corrosion resistance of the cast material is somewhat lower than the wrought material especially at higher concentrations and temperatures in sulfuric acid. In this paper, all corrosion and mechanical data, including Table 4, used Zircadyne® zirconium.(1)

CHEMICAL COMPOSITION DIFFERENCES

(Table in full paper)

Zr 702C and Zr 705C cast zirconium is normally produced according to ASTM B752 “Standard Specification for Castings, Zirconium-Base, Corrosion Resistant, for General Application”. Zirconium sheet and plate is normally produced according to ASTM B751 “Standard Specification for Zirconium and Zirconium Alloy Strip, Sheet, and Plate”. Table 1 gives the chemical requirements as specified in these ASTM standards.

PHYSICAL AND MECHANICAL DIFFERENCES

Table 2 gives the physical and mechanical differences between these two zirconium alloys 2. Notice that the Zr 705 is actually a two phase alloy as opposed to Zr 702 which, for practical purposes, has a single phase.

This paper highlights the coordinated AC mitigation and cathodic protection strategy for a 167 mile (269 km) long high-pressure interstate natural gas pipeline. Ninety-five percent of the pipeline is located adjacent and parallel to high voltage AC power transmission lines ranging to 500 kV. Analyses and computer simulations during the front-end engineering design predicted that, without suitable mitigation, steady-state AC potentials (referenced to local earth) on the pipeline would easily exceed 100 V; AC coating stress and touch potentials approaching 12,000 V were predicted during a power line to ground fault. The AC mitigation and cathodic protection designs were closely coordinated with operations personnel to assure systems that were maintenance-friendly. Corrosion control commissioning included a multi-channel AC and DC close interval potential survey protocol. The baseline data document the success of the AC mitigation and cathodic protection in safely and cost effectively controlling soil corrosion and AC interference. Long-term surveillance includes state-of-the-art remote monitoring and the use of coupon technology.

INTRODUCTION

The subject 167 mile (269 Km) long pipeline parallels and crosses various overhead 3-phase high voltage AC power transmission lines with phase-to-ground voltages ranging from 115 to 500 KV. Four power companies are involved. The limits of each power line circuit along with their steady-state line currents and maximum estimated fault currents are shown in Table 1. The photograph in Figure 1 shows some of the power lines along a portion of the right-of-way. The lateral separation distance between the pipeline and the closest power line varies from approximately 75 to 150 feet (23 to 46 m). The pipeline crosses under one or more of the power lines twenty-eight times. There were no power line phase transpositions.

Recognizing the complexity of the right-of-way relative to electrical interference, the pipeline owner authorized an engineering evaluation of the anticipated AC effects as part of the project design. This included estimating the AC impacts on the pipeline without mitigation and developing a mitigation design strategy to safely and reliably operate the pipeline without excessive pipe potentials or unnecessary concern regarding AC corrosion. The AC evaluation and mitigation design were effectively coordinated with the cathodic protection and other aspects of the design to assure a total systems approach. Key aspects to the success of the design included routine information exchange between all parties involved: the pipeline owner's project manager, the pipeline designer, the AC mitigation and corrosion control engineer, the pipeline corrosion control staff, and the four power companies. This was particularly critical when pipe alignment changes were necessary during the design and as the construction of the pipeline got underway.

AC MITIGATION DESIGN METHODOLOGY

Soil resistivity data were collected along the pipeline right-of-way at nominal 1 mile (1.6 Km) intervals and at power line crossings. The Wenner 4-pin measurement technique (ASTM G57) was used at each test location to determine apparent soil resistivities at different depths ranging to 100 feet (30 m). The soil resistivity data along with the relative geometry between the pipeline and the different power lines.

The use of titanium plate heat exchangers is widespread for Offshore and Coastal installations where seawater cooling is required. Several years ago difficulties to supply titanium Grade 1 for this application triggered the need for qualification of other alloys for this application. Applications using passive alloys are especially susceptible to crevice corrosion when exposed to hot seawater. Since titanium is the most corrosion resistant alloy in seawater only highly corrosion resistant alloys could be considered for its replacement in plate heat exchangers. In addition since they need to be shaped into plates by cold pressing only alloys with a high formability could be selected. This narrowed even further candidate alloys for plate heat exchangers. In this study nickel chromium molybdenum alloys and a highly alloyed stainless steel were tested between 30 and 70°C in natural seawater with up to 1 ppm free chlorine. Rather than using short term electrochemical testing that is often difficult to compare with service performance long term exposure tests (up to 18 months) of real plate heat exchangers were carried out. These tests are considered to be more representative of actual service conditions. The results of these tests and their significance are discussed and compared with previous reported work.

INTRODUCTION

Many industrial sites such as oil and gas production facilities are located on the sea shore and offshore. These facilities use seawater as a cooling medium because of its immediate availability. The cooling of fluids is a full part of the process through the use of tubular and plate heat exchangers (PHE's). Direct seawater cooling is normally used to limit cost and save space and weight. Titanium alloys are usually the preferred choice for seawater cooled heat exchangers because of their outstanding corrosion resistance even in hot aerated seawater and their good strength and low density. In particular low pressure seawater cooling is usually accomplished using PHE's made of Grade 1 titanium. This grade is used because of its good formability. Grade 2 is typically utilized in tubular HE.

Several years ago new projects had difficulty securing deliveries of titanium Grade 1 for PHE's because of a high demand on the market and limited production capabilities. As a consequence it was decided to look for potential replacement alloys for this application. Two major properties are normally required for use as a PHE material: a good cold formability to easily press the plates into shape and an excellent corrosion resistance because very severe crevices are present in particular under the elastomer gasket seals. In addition the required plate thickness is low with typical values between 0.5 and 0.7 mm. This means that any localized corrosion would quickly lead to HE leaks which could have very serious consequences in terms of loss of production.

This study was designed to investigate the effects of temperature, crevice tightness, and the addition of chlorine on service life because each of these parameters accelerates seawater crevice corrosion.

Increasingly, new systems are installed and used in harsh conditions such as installations with high expected ground movements, reeled offshore pipe lays, high pressure/high temperature (HPHT) service conditions and pipelines with occasional pressure spikes above the material yield strength. As a result of these demanding applications, the utility and necessity of strain-based design (SBD) has increased. To evaluate SBD components, testing methodologies need to correlate real material performance data to calculated design limits. One realistic test method for simulating the corrosion/mechanical failure conditions of SBD components is the cyclic slow strain rate test (CSSRT), alternatively named the ripple strain rate test (RSRT).

This paper documents the RSRT evaluation of UNS N06625 weld overlay material applied to low grade carbon steel for potential applications in an SBD oil and gas production situation containing high H2S and CO2 partial pressures as well as very oxidizing environments. The test methods (involving liquid H2S loading) are discussed in more detail. In addition, RSRT results will be compared with electrochemical testing in highly oxidizing environments containing ferric chloride at high temperatures (critical pitting and crevice temperatures following a modified version of the ASTM G48). Overall, the goal is to develop a rapid pre-screening, ranking and suitability process for Highly Corrosion Resistant Alloy (HCRA) or HCRA-clad materials that can take into consideration their corrosion resistance to highly corrosive environments and include mechanical strength testing of the desired material.

These main objectives help qualify suitable materials and processes that can be used in the Oil and Gas industry. This is particularly true for highly corrosive and high stress environments where the current international standards do not contemplate the high levels of H2S, high CO2 partial pressures and oxidizing environments together with strain-based loads.

INTRODUCTION

Increasingly, new applications for oil and gas require materials or combination of materials that are typically installed in harsh conditions such as installations with high expected ground movements, reeled offshore pipe lays, high pressure/high temperature (HPHT) service conditions and pipelines with occasional pressure spikes above the material yield strength[1],[2]. As a result of these demanding applications, the utility and necessity of strain-based design (SBD) has increased[1],[2],[3],[4],[5]. To evaluate SBD components, testing methodologies need to correlate real material performance data to calculated design limits. One realistic test method for simulating the corrosion/mechanical failure conditions of SBD components is the cyclic slow strain rate test (CSSRT), alternatively named the ripple strain rate test (RSRT). This method allows the evaluation of the performance of a given material with regard to stress corrosion cracking (SCC) and sulfide stress cracking (SSC) in the plastic regime without the undue material selection conservatism from the severe (and commonly utilized) slow strain-rate (SSRT) loading6. The principle of the RSRT is to repetitively impose a small (plastic) deformation under tensile load on a metal specimen while it is exposed in an autoclave to a simulated worst-case operating condition (at high temperature and pressure).

Organic coatings are widely used in ship structure for corrosion protection and IMO PSPC Guideline has recently been issued to achieve high anti-corrosion properties. Currently, solvent borne epoxy paints are generally used in ship coating, especially water ballast tank (WBT) and the emission of volatile organic compound (VOC) materials such as hydrocarbon solvents is inevitable. Evaporation of solvent was known as pollutant material and resulting in hazard to health of spray worker. Therefore, the current trend is toward the application of lower VOC coating material, especially solvent free coating containing solvent less than 5% or water borne paint for environmental and human protection. Additionally, multi-coating system of ship coating including 2- main coating and 2-strip coating was also raised as one of reason for air pollution.

In present study, the performances of commercially used solvent free epoxy paint with 1-main coating and 1-stripe coating has been evaluated comparing with those of commercially used solvent-borne paint with 2-main coating and 2-strip coating in terms of anti-corrosion, build-up properties, crack resistance and contents of volatile organic compound. From the results, it would be clearly indicated that solvent free epoxy coating showed equivalent or higher anti corrosion and build up performances than solvent borne epoxy.

INTRODUCTION

The shipbuilding consists of many process including welding, cutting, painting, assembling and outfitting, etc. The steels are welded and assembled to block structure and it was coated by anticorrosion paint, usually solvent borne epoxy paint.

Water ballast tank is a compartment within a ship, which holds sea water. A large ship typically has several ballast tanks including double bottom tanks. A ballast tank can be filled or emptied in order to adjust the buoyancy. Water ballast tanks are most demanding of effective corrosion protection systems because it exposes to the most severe corrosive environment including sea water immersion, wet / dry cycling, etc. In view of high corrosive environment exposure of ships, especially water ballast tank the importance of anti-corrosion performance of paint, whose performance is closely related to ship's safety and lifetime, has led to the development of higher anticorrosive performance paint. Plenty of solvent based paints have been developed in order to increase the quality of corrosion protection for ship structure. In addition, IMO performance standard for protective coatings (hereafter, called as PSPC) has been recently issued to achieve better quality by controlling paint application procedure more tightly [1].

In spite of such advancement, solvent-borne epoxy paints, which are currently used as anti-corrosive paint in shipyard, still have disadvantages in the points of environmental protection and material performance because of solvent evaporation. The solvent-borne epoxy paints contain large quantity of volatile organic compounds (VOC) such as hydrocarbon solvents including Toluene and MEK, etc, and its emission to atmosphere is inevitable, finally resulting in air pollution. Another concern is possible solvent entrapment, especially in low temperature drying condition which can affect the long term anti-corrosion performance.

Produced fluids from deep, hot gas wells are often accompanied by low molecular weight organic acids in Australia, Japan in addition to Southeast Asia regions. Influences of organic acids on corrosion performances of corrosion resistant alloys (CRAs) are evaluated in high temperature sweet environments. It is considered that organic acids, such as acetic acid, have some adverse effects on the protectiveness of passive films (oxides and/or sulfides), in addition to the pH lowering effect.

In this present study, influences of acetic acid on localized corrosion performances of Supermartensitic 13Cr, 15Cr, and 22Cr Duplex stainless steels (SS) have been investigated using electrochemical techniques, weight-loss measurements and slow strain rate tests in sweet environments at ambient temperature and 180oC.

INTRODUCTION

Organic acids are often contained in produced fluids from gas-condensate wells in Australia, Japan and Southeast Asia etc. Table 1 shows the concentrations of low molecular weight organic acids in produced waters from Minami-Nagaoka gas/condensate wells in Japan. These wells have higher acetic acid concentrations compared with other organic acids. The presence of acetic acid has some important effects on CO2 corrosion. Several researchers have reported an increase in CO2 corrosion rate of carbon steel and Cr bearing steels in the presence of acetic acid1-7.

It is considered that localized corrosion of carbon steels is accelerated due to pH decrease when organic acids are present in corrosive environments8. Organic acids actually contribute to Top Of Line Corrosion (TOLC) in subsea pipelines9-10 and performance of corrosion inhibitors. Moreover, presence of acetic acid is considered to be a very important factor that caused the localized corrosion of 13%Cr SS tubing in Minami-Nagaoka gas field11 and in laboratory experiment3.

Many reports provided by steel manufacturers indicate that the corrosion resistance of 13% Cr SS (L80-13Cr: UNS S42000) in CO2 environments strongly depends on temperature12-14. The corrosion resistance is very high and stable at temperatures below 150 oC. However, in the temperature range above 150 oC, the corrosion resistance of the steel apparently decreases with the increase in temperature. Therefore 150 oC has been defined as a critical temperature for using 13%Cr SS by steel manufactures15-17.

From our field experience, the observed uniform corrosion rate of the steel was much lower than those data provided by steel manufactures14 at high temperatures. However at shallow depths of Minami-Nagaoka wells, where temperatures were lower than 120oC, severe localized corrosion was found on 13%Cr SS. It may be due to the low pH caused by high CO2 solubility at low temperatures and the existence condensation of acetic acid. This fact is in contradiction to the traditional understanding that the corrosion performance of 13% Cr SS deteriorates at high temperatures in wet CO2 environments.

Recently, some steel manufactures commercialized Super Martensitic Stainless steels (SMSS) such as Supermartensitic 13Cr Stainless Steel18-19 (S13Cr SS: UNS S41426) and 15Cr SS20 (15Cr-6Ni- 2Mo) which contain Ni and Mo. These CRAs have high CO2 corrosion resistance even at high temperatures and high strength properties.

This paper traces the development of the superaustenitic grade 254 SMO (UNS S31254) as a solution to recurrent corrosion problems within the pulp and paper industry. The composition of 20Cr 18Ni 6.1Mo 0.2N imparts a high corrosion resistance, but has also presented challenges such as development of good welding practice. Examples are given from different field tests within the industry and from extensive subsequent application to chlorine (C) and chlorine dioxide (D) stages in bleach plants. For a long period S31254 was used as a regular construction material for filter washers. Due to environmental concern the most aggressive stages have gradually been replaced with chlorine-free agents that are less harmful to stainless steel and need less high performance material. Superduplex steel has also become established as an economic alternative but S31254 has found new applications in offshore applications, flue gas cleaning and hydrometallurgy.

INTRODUCTION

The early development of stainless steels was closely linked to needs in the process industry. Particularly in Nordic countries the pulp and paper industry was a dominating industry that influenced the requirements for stainless steels. It is often said that the molybdenum addition to austenitic steels to make them “acid-proof” was directly associated to the aggressive, acid cooking liquor in sulfite digesters. Acid-proof stainless steels were used to a great extent in most stages of the sulfite mills. For the digesters austenitic stainless steels with high molybdenum contents, to over 4%, were used to reduce the corrosion rates and increase the service life. Later developments in pulping resulted in the alkaline sulfate (kraft) process becoming predominant with less need for molybdenum-alloyed grades.

However, the requirements for highly resistant alloys increased in the pulp-bleaching stages where chlorine and chlorine dioxide bleaching and closed process systems made the environment extremely aggressive to stainless steel. In practice none of the commercially available stainless steels could withstand the most severe conditions and nickel-base alloys or titanium had to be selected for acceptable performance. There was therefore a clear demand for a stainless steel with higher pitting and crevice corrosion resistance than that provided by existing grades. Addition of high amounts of chromium and molybdenum caused problem with intermetallic phase formation. At that time, the positive influence of nitrogen on austenite phase stability and pitting corrosion resistance of austenitic stainless steels was known, but this behavior was only marginally utilized in commercial steels.

The introduction in early 1970's of the Argon Oxygen Decarburization (AOD) process in the stainless steel industry facilitated the deliberate nitrogen addition in the melt shop and opened new possibilities for stainless steel alloys. The intention with this paper is to describe the development of the 6Mo superaustenitic grade 254 SMO (UNS S31254), which was linked to the needs in pulp and paper industry, and to show examples of its use in pulp and paper and several other applications over more than 30 years.

ALLOY DEVELOPMENT WORK

The most resistant commercial austenitic stainless steels in early 1970's were type 904L (UNS N08904) and 317 LMN (UNS S31726).